Background description of wettability is presented, for example, in Freedman et al., SPE Paper 77397, present at the 2002 meeting of Society of Petroleum Engineers. As described therein, wettability is the tendency of a fluid to spread on and preferentially adhere to or “wet” a solid surface in the presence of other immiscible fluids. Knowledge of reservoir wettability is critical because it influences important reservoir properties including residual oil saturation, relative permeability, and capillary pressure. An understanding of the wettability of a reservoir is crucial for determining the most efficient means of oil recovery. This is becoming increasingly important as more secondary and tertiary recovery projects are being undertaken to recover remaining reserves after primary production. It is generally believed that most reservoirs are water wet or mixed wet. In mixed-wet rocks the brine phase occupies the smaller pores, which are therefore water wet. In the larger oil- and brine-filled pores the oil wets part of the pore surfaces.
Two widely used laboratory indicators of wettability are contact angles measured in water-oil-solid systems and the Amott wettability index. A practical limitation of contact angle measurements is that they are restricted to special geometries and cannot be made on reservoir rocks. The Amott wettability index is determined from the amount of oil displaced from a core, starting at some initial oil saturation, by spontaneous imbibition of brine divided by the amount of oil displaced by both spontaneous and forced imbibition. Amott defines an analogous index by also considering the displacement of water by oil. The Amott indices vary linearly on a scale from 0 to 1. The endpoints for the displacement of oil by water are 0 for a neutral to oil-wet system and 1 for a strongly water-wet system. Imbibition measurements like the Amott index provide the most quantitative indicators of wettability, but they are limited to the laboratory.
NMR measurements on fluid-saturated porous media are sensitive to wettability because of the enhanced relaxation rate caused when fluid molecules come into contact with pore surfaces that contain paramagnetic ions or magnetic impurities. Surface relaxation of nuclear magnetism is usually the dominant relaxation mechanism for the wetting phase in a partially saturated rock. The nonwetting phase is unaffected by surface relaxation because the pore surface is coated by the wetting fluid. The other relaxation mechanisms, bulk and diffusion relaxation, affect both the wetting and nonwetting phases. The relaxation rate of the transverse magnetization measured in a spin-echo experiment is the sum of the relaxation rates from all three mechanisms. The bulk relaxation rates for liquids are proportional to their viscosities.
Freedman et al. U.S. Pat. No. 6,765,380, assigned to the same assignee as the present application, had pointed out that many laboratory NMR wettability studies have been reported in the literature, but that reservoir wettability determination from laboratory measurements is not definitive because it is not possible to accurately mimic reservoir conditions in the laboratory. In fact, the very processes required to obtain laboratory samples can alter the reservoir wettability.
The referenced '380 patent disclosed a method for determining reservoir wettability under downhole conditions. The technique thereof involved using an NMR logging tool to acquire a first set of NMR measurements of formation fluids in earth formations at a selected axial depth and inverting the first set of the NMR measurements to produce a first distribution of a spin relaxation parameter for a fluid component in the formation fluids. A formation fluid testing tool is used to obtain a formation fluid sample, and a second set of NMR measurements are made on the fluid sample. The second set of NMR measurement is inverted to produce a second distribution of the spin relaxation parameter for the fluid component in the formation fluid sample.
As described further in the '380 patent, the method thereof involves joint interpretation of diffusion measurements made by conventional NMR logging tools and NMR measurements made in the flowline of a fluid sampling tool. The diffusion measurements are used to separate the NMR oil and water signals from the fluids contained in the rock pore spaces. The conventional NMR tool diffusion measurements are inverted in the method of the '380 patent to compute separate oil and water relaxation time distributions. As described therein, the inversion can be performed using the technique disclosed in Freedman U.S. Pat. No. 6,229,308, the technique being known as the “magnetic resonance fluid characterization method” or “MRF method”. As described in the '308 patent, the MRF method is a diffusion-based inversion that requires accurate knowledge of the magnetic field gradient in the pore spaces of the rock investigated by the NMR tool.
The computation of T1 and T2 distributions of reservoir oil contained in reservoir rock is fundamental to the '380 patent. The diffusion method for computing oil relaxation time distributions in the pore spaces of reservoir rocks can be problematic if the NMR magnet induces internal magnetic gradients in the rock. In this case the magnetic field gradients in the pore spaces are not known and the diffusion method employed in the '380 patent has limitations in computing accurate water and oil relaxation time distributions. Induced internal gradients are commonly encountered in sandstone formations because of the presence of iron and/or other magnetic minerals. For example, iron is present in chlorite, a clay mineral commonly found in sandstone rocks. Because of induced gradients, the method of the '380 patent may not always be reliable in sandstone formations. Another limitation of the diffusion method used in the '380 patent occurs when the reservoir oil and water have nearly identical diffusion coefficients and overlapping relaxation time distributions.
It is among the objectives of the present invention to overcome problems and limitations of prior art techniques, including those summarized above.